EP2260177B1 - Überwachung von sich entlang strömungswegen in einem produktionsölfeld bewegendem reservoirfluid unter verwendung von passiven seismischen emissionen - Google Patents

Überwachung von sich entlang strömungswegen in einem produktionsölfeld bewegendem reservoirfluid unter verwendung von passiven seismischen emissionen Download PDF

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EP2260177B1
EP2260177B1 EP09713844.0A EP09713844A EP2260177B1 EP 2260177 B1 EP2260177 B1 EP 2260177B1 EP 09713844 A EP09713844 A EP 09713844A EP 2260177 B1 EP2260177 B1 EP 2260177B1
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Prior art keywords
microseismic events
water
oil
during
reservoir
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EP2260177A4 (de
EP2260177A2 (de
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Shivaji N. Dasgupta
Saleh Al-Ruwaili
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Saudi Arabian Oil Co
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Saudi Arabian Oil Co
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
    • G01V1/30—Analysis
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/12—Signal generation
    • G01V2210/123—Passive source, e.g. microseismics

Definitions

  • the present invention relates to a method of monitoring reservoir rock containing hydrocarbons, and in particular to a method and system for the identification of the type of liquid moving along flow pathways of a producing field using passive seismic emissions.
  • Microseisms in reservoir rock matrixes in producing oil fields are generally the result of pore pressure perturbation and geomechanical stress field relaxation due to liquid movement as reservoir fluids are produced and/or injected.
  • the microseisms or micro-earthquakes, are generated because the stress field in the reservoir, and fluid flow, is anisotropic.
  • the anisotropy is generally due to heterogeneity in reservoir rocks. Existence of joints, bedding planes, faults, and fractures are common in sedimentary rock. In most reservoirs, the in-situ stress conditions due to overburden pressure keep these features closed to fluid flow.
  • changes in fluid pressures result in perturbation of the in-situ stresses.
  • microseisms follow the same laws of physics for generation and transmission as do natural earthquakes.
  • Microseisms result from elastic rock failure of the reservoir rock matrix.
  • the micro-earthquakes are due to shear stress release along zones of weakness in the rock formation.
  • the stress release is due to perturbation caused by reservoir production and injection operations.
  • Water injection generates increased reservoir pore pressure which causes an increase in shear stress in reservoir rocks. This impacts the stability along the planes of weakness present in reservoir rocks, such as joints, bedding planes, faults and fractures.
  • reservoir oil production operations or fluid withdrawal create a pore pressure sink which also affects the stability along the zones of weakness.
  • Seismic waves from microseismic events are transmitted from the source location (or hypocenters) to remote sensors (or seismometers). The hypocenters of microseismic events correspond with locations of elastic rock failure that form the fluid conduits.
  • r 4 ⁇ Dt
  • microseisms are detected in multi-component seismic sensors with wide bandwidth, over distances of 1 kilometer and greater.
  • fluid flow monitoring including the assessment of changes in the reservoir characteristics over the production time, is achieved with measurements in selected wells using downhole instrumentation at selected production time intervals.
  • a method for locating microseismic sources is disclosed in US Patents 6,049,508 and 6,920,083 .
  • Recorded microseismic waves consist of records of compressional waves, known as P-waves and shear waves, known as S-waves.
  • the first arrival times of recorded P-waves and S-waves, and the velocities of the rock layers, are used to compute source location or hypocenter microseisms where the rock failure occurred.
  • For each microseismic event it is first necessary to determine the fault plane and slip direction (source mechanism) before investigating for source parameters.
  • Such source location technique is implemented by identifying and classifying the first arrival time breaks and measuring arrival times of P-waves and S-waves.
  • the amplitudes of these P and S-waves are detected and the seismograms are recorded.
  • polarization analysis is performed. with hodograms or terminus of a moving vector for particle motion of the waves recorded in the three component sensors which are oriented orthogonally in the sensor package.
  • the polarization analysis consists in measuring the spatial distribution of a three component (right-normal basis) signal over a time window using the covariance matrix. Most of the time, the results used are the "azimuth" and the dip inclination of the distribution main direction which is defined by a vector. This analysis determines the direction of a wave's approach to the three component sensors or detectors that are planted precisely with a known orientation.
  • US Patent 7,127,353 describes a method for monitoring seismic energy emitted from the reservoir. Monitoring the changes in seismic energy emission in response to pressure changes in the active well and altering the values of the processing parameters permits measurement of components of the permeability tensor. Changing fluid pressure causes seismicity to rapidly migrate outward from the points of fluid pressure change and will alter the characteristics of the seismic energy emission.
  • US Patent 5,377,104 describes an arrangement of seismic sensors to detect passive microseismic events induced in reservoir by hydraulic fracturing.
  • the disclosure provides a system and method of monitoring and verification of the geologic containment of hydraulically induced fractures used for the disposal of hazardous wastes , to avoid cross contamination with water source.
  • a network of sensors distributed spatially on the surface and at different levels in a borehole records a number of arrival times n, for P-waves and S-waves from a microseismic event with hypocenter parameters (x,y,z,t).
  • AX B
  • A is the nx4 design matrix of partial differentials
  • X is a vector of 4 unknown hypocenter parameters (x,y,z,t)
  • B represents vector differences between the calculated and observed travel times arrival.
  • the design matrix determines the efficiency of the network. For a given matrix A and a set of observations of B, the equation will solve for unknown vector X.
  • the partial differentials define how much the hypocenter parameters will change with respect to travel times.
  • a permanent network 70 including cemented geophones 72 that are deployed spatially on the ground surface and geophones 64 that are installed in a borehole monitor well 80, is used to record microseisms 76.
  • the system continuously detects and records the passive micro-earthquakes or microseismic events emanating from the reservoir as fluids are produced and injected at a location 78 from an injection well 82.
  • the location in (x,y,z) coordinates for each microseismic event that is detected by the surface and borehole sensors is derived and its time of occurrence T o is obtained from Global Positioning System (GPS) time stamps from the recording system.
  • GPS Global Positioning System
  • the plurality of sensors in a high density network provides the redundancy in the recorded data and improves the accuracy in the source location of the detected events.
  • US Patent 7,242,637 assigned to Shell Oil Company describes a time-lapse seismic survey process for investigating a subsurface reservoir region.
  • the disclosure identifies water contact lines in the seismic representations, and also discusses a model that includes a sea water layer.
  • these models do not detect passive microseismic emissions based upon movement of fluids.
  • US Patent 6,614,717 assigned to Nonlinear Seismic Imaging, Inc. also describes a time-lapse seismic imaging method.
  • This reference discloses the viscosity difference between oil and water, and notes that hysteresis at seismic frequencies is related to the viscosity of the pore fluids.
  • this reference relates to seismic imaging in a system including an active seismic source and receiver. There is no disclosure in the reference related to measurement or monitoring of passive microseismic emissions.
  • US Patent 6,498,989 and related US Patents 6,028,820 and 5,796,678 all assigned to Trans Seismic International Inc., describe a wave equation based on a discrete dynamic model that uses stress conditions as target parameters, which are used to discover oil and gas pools, as well as water reserves.
  • the product data set from the equation can be outputted in the form of an initial isochron map, a pressure gradient map, a corrected isochron map, or an overlay of the relative pressure changeability map and the corrected isochron map, which are the basis for identifying the most probable locations of oil, gas, and water.
  • the processes proposed in these references are for locating fluid accumulations from seismic imaging of subsurface regions, and presupposes a seismic reflection survey. Direction of fluid flow is inferred indirectly from the reflection surveys. There is no disclosure of monitoring of passive microseismic activity.
  • Patent Publication US2008/0151691 assigned to Schlumberger Technology Corporation discloses methods of passively monitoring microseismic events, which can be applied to hydrocarbon reservoirs and subterranean water-bearing layers.
  • this disclosure relates to monitoring of hydraulic fracturing or reservoir stimulation using passive microseismic recordings, and does not in any way attempt to discern the type of liquid moving along a certain pathway in a reservoir.
  • US Patent 6,941,227 assigned to the Regents of the University of California describes frequency-dependent method for processing seismic data.
  • One aspect of the disclosure relates to identifying an oil-water contact.
  • this disclosure relies upon reflection surveys, and the frequency spectrum is analyzed from the acquired reflection data from a fluid filled reservoir and correlated with known accumulations.
  • the term fluid means a liquid that is predominantly oil or predominantly water, either of which may contain minor amounts of the other and dissolved gas.
  • the term fluid means a liquid that is predominantly oil or predominantly water, either of which may contain minor amounts of the other and dissolved gas.
  • the above objects and further advantages are provided by a method for determining whether a liquid moving in an oil-bearing reservoir rock formation is water or oil according to claim 1.
  • the oil-bearing rock formation includes at least one production well and at least one source of injected water during normal oil production.
  • a preferential fluid pathway is identified.
  • a baseline number of passive microseismic events per a predetermined unit of baseline time is established.
  • Passive microseismic events in the preferential fluid pathway are monitored during normal oil production to sense a number of microseismic events during a predetermined unit period of monitoring time. The sensed number of microseismic events during the predetermined unit period of monitoring time are compared to the baseline number of passive microseismic events per the predetermined unit of baseline time.
  • the fluid causing the microseismic events is determined to be water if the sensed number of microseismic events during the predetermined unit period of monitoring time approaches the baseline number of passive microseismic events per the predetermined unit, and if the baseline number of passive microseismic events per the predetermined unit baseline time is measured during a time period when the water injection is greater than the rate of water injection during normal oil production.
  • the fluid causing the microseismic events is determined to be oil if the sensed number of microseismic events during the predetermined unit period of monitoring time approaches the baseline number of passive microseismic events per the predetermined unit, and if the baseline time is measured during a time period when the water injection is less than the rate of water injection during normal oil production.
  • the baseline is a quiet period, either following a ramped up water injection period, or following water injection at rates associated with normal oil production in reservoirs in periods of secondary recovery.
  • the quiet period can be used to establish a baseline which is important for controlling the monitoring operations and interpreting the seismic data during the monitoring period.
  • the present invention relates to an improved method for reservoir monitoring, including identification of the fluid phase (oil or water) moving along flow pathways of hydrocarbon drainage and water movement in a reservoir. These flow pathways are generally along fracture swarms or other zones of weakness in reservoir rock. Microseismic events are detected along these zones of mechanical weakness as the fluids move in the reservoir rocks. Fluids are injected into, or extracted from, a producing reservoir with anomalous flow anisotropy. Water or brine is injected in the pore volumetric space of reservoir rocks to enhance oil production from the reservoir.
  • the method of this invention is useful for flood-front mapping in a black oil reservoir system consisting predominantly of oil and water (brine). It is assumed that no free gas is present in the system.
  • Reservoirs containing oil and water, with a low gas-to-oil ratio (GOR) are abundant in giant carbonate fields. Th ese carbonate rocks are extremely heterogeneous and many drilled wells have encountered anomalous fluid flow conduits, or pathways, along narrow fracture swarms. These features contribute to a flow anisotropy that cannot be determined from borehole data alone. Usually, the well spacing in such giant oil fields is sparse. Flood-front monitoring away from and between wells is imperative for optimum reservoir management and for increasing overall recovery. In a producing reservoir, mapping hydrocarbon fluid pathways and identifying respective liquid phase (oil or water) moving along such flow pathways, is crucial for improving and increasing oil recovery.
  • This invention is particularly useful in a producing reservoir to continuously define the map of preferential fluid movement directions (pathways) and also to identify the type of fluid moving along these preferential pathways.
  • the flow pathways and the fluid phase moving along these pathways between wells cannot be measured easily using conventional measurements in drilled wells.
  • the method of the present invention provides the orientation and distribution of preferential fluid pathways and identifies the fluid phase, differentiating between oil or water moving along the pathways.
  • the mapping of fluid pathways and the identification of the type of fluid is useful to optimize fluid injection and production operations and improving overall oil recovery.
  • the detected passive seismic emissions in certain embodiments recorded and analyzed in real time, can define fluid flow pathways between the wells in a producing field.
  • the water flood-front movement is often more complex, non-uniform and unpredictable.
  • Fluid flow simulation provides stochastic models for the flood-front using data only at well control points.
  • the hydraulic parameters inferred from fluid-induced microseismic data can be used as fluid monitoring information. This data is used for optimizing reservoir management and exploitation.
  • the mobility of water through these reservoir conduits in an oil reservoir is much higher than oil. This is primarily because oil has higher viscosity than water. In on oil-bearing reservoir rock formation, the mobility ratio can be obtained with proper special core analysis, commonly known to those skilled in the art as "SCAL". For instance, oil originating from the Jurassic carbonate formations has a viscosity that is about three (3) times higher than that of water. In a reservoir that is at an intermediate stage of water flood recovery, the relative permeability of water and oil are approximately equal. This means that the mobility of water is about three (3) times that of oil in this reservoir. Therefore, the water is expected to travel faster than oil, especially in high permeability pathways such as fracture swarms.
  • the fluid flow potential through porous rocks in oil reservoirs is measured by permeability.
  • Q ph is the rate (volume/time) at which phase ph, e.g. oil, or water, having viscosity ⁇ ph and relative permeability k r,ph flows across an area A within a reservoir having rock absolute-permeability K , when pressure drop ⁇ P is exerted on the phase ph over a distance ⁇ X i perpendicular to the area A.
  • Darcy's equation equates the flow rate Q ph to the pressure gradient ⁇ P / ⁇ X i multiplied by the transmissibility ( K ⁇ k r,ph ) A / ⁇ ph .
  • the factor ( K ⁇ k r,ph ) is the effective permeability of the reservoir rock relative to the phase ph.
  • the factor ( K ⁇ k r,ph ) / ⁇ ph is the mobility of the phase ph (oil or water) in the reservoir rock.
  • the factor K ⁇ k r,ph is the effective-permeability of phase ph in the reservoir rock, and may be abbreviated as k ph .
  • M w K ⁇ k r , w / ⁇ w
  • K is the absolute permeability of water in units of area
  • k rw is the relative permeability of water (unitless)
  • ⁇ w is the viscosity of water in units of (force)(time)/(area) or in (pressure) (time).
  • M o K ⁇ k r , o / ⁇ o
  • K is the absolute permeability of oil
  • k ro is the relative permeability of oil
  • ⁇ o is the viscosity of oil
  • M w is greater than M o .
  • water moves much faster than oil in a high-permeability conduit, leading in many cases to premature water breakthrough in certain production wells.
  • Fast water movement in preferential reservoir pathways e.g. fracture swarms, conduits, and channels, will be associated with shear elastic failures, i.e., microseismic events, that are detectable in a specific time period ⁇ t of interest to monitor the reservoir.
  • microseisms associated with water movement, M w will have higher magnitude than those associated with oil, M o , moving in such reservoir pathways. This attribute can also be employed in an alternative embodiment described in greater detail below.
  • N w (Nmicroseisms) w / ⁇ t and N o ⁇ (Nmicroseisms)o / ⁇ t, than: N w > N o in reservoirs having higher water mobility than oil mobility.
  • FIGs. 1A and 1B schematically illustrate a process flow of a method of identifying whether a liquid moving in a reservoir rock is water and/or oil.
  • passive microseismic events are generally not attributable to movement of water or oil through anisotropic fluid pathways in the reservoir rock.
  • steps 30 through 40 are carried out to determine and map the number of passive microseismic events attributable to water flow during a rate of water injection that is less than a water injection rate during steady-state oil production, and to determine and map the number of passive microseismic events attributable to water flow during a rate of water injection that is greater than a water injection rate during normal periods of oil production.
  • the microseismic event data transmitted from the sensors are received and recorded in a seismic server for processing and for storage, for example, in a data or disk storage device, or alternatively stored locally at each sensor and transmitted at a predetermined time to a seismic server for processing.
  • step 30 when water injection 22 is reduced, or ramped down 26, data is inputted 30 related to sensed passive microseismic events in the oil-bearing reservoir rock region from sensors 20.
  • the ratio N o of the number of microseismic events during a predetermined unit period of time is identified 32, and these events are mapped 34 to illustrate a preferential flow pathway.
  • data is inputted 36 related to sensed passive microseismic events in the oil-bearing reservoir rock region from sensors 20.
  • the ratio N w of the number of microseismic events during a predetermined unit period of time is identified 38, and these events are mapped 40.
  • One or both of these ratios N w and N o can be used as baseline values for comparison to the number of events per predetermined unit of time during continuous monitoring as further described below.
  • the ratio N m of the number of microseismic events during a predetermined unit period of time is identified 44.
  • the predetermined unit period of time can be on the order of one or more hours or one or more days, and may be the same or different for the ratios N m , N w and N o .
  • the ratio N m is compared 46 to the ratios N w and N o .
  • microseismic events will occur. If it is determined 48 that the ratio N m is closer to the ratio N o than to the ratio N w , the microseismic events can be identified 50 as being attributable to oil movement along the preferential flow pathway. Conversely, if it is determined 52 that the ratio N m is closer to the ratio N w than to the ratio N o , the microseismic events can be identified 54 as being attributable to water movement along the preferential flow pathway.
  • the relative magnitudes of the sensed microseismic events can be used to provide further confidence in the determinations of the identities of the fluid moving along the flow pathway.
  • the magnitude level R o is determined 55 and mapped 34.
  • the magnitude level R w is determined 56 and mapped 40.
  • the magnitude level R m is determined 58.
  • the magnitude level R m is compared 60 to the magnitude levels R w and R o . If it is determined 62 that the magnitude level R m is closer to the magnitude level R o than to the magnitude level R w , the microseismic events can be identified 64 as being attributable to oil movement along the preferential flow pathway. Conversely, if it is determined 66 that the magnitude level R m is closer to the magnitude level R w than to the magnitude level R o , the microseismic events can be identified 68 as being attributable to water movement along the preferential flow pathway. Note that these determinations 62, 66 are be used to supplement the determinations 48, 52 made in the process flow as shown in FIGs. 1A and 1B .
  • the location of the microseismic events is preferably determined with a plurality of microseismic sensors located on the surface, within a borehole, or both on the surface and in a borehole.
  • a plurality of microseismic sensors located on the surface, within a borehole, or both on the surface and in a borehole.
  • the system and method described in commonly assigned PCT Publication WO 2007/0562278 can be advantageously employed to monitor reservoir fluid movement and determine the locations of microseismic events.
  • methods for locating microseismic sources as disclosed in US Patents 6,049,508 , 6,920,083 , 7,127,353 , and in the publications by Lee et al. and Raymer et al. can be used to determine the sources, provided that the methods include the determination of magnitudes and frequencies of microseismic events.
  • a network 70 included a grid of equally spaced seismic sensors 72 permanently cemented and deployed spatially on the ground surface and additional sensors 74 cemented in one or more borehole or monitor wells 80, as described in commonly assigned PCT Publication WO 2007/0562278 .
  • passive micro-earthquakes, or microseismic events 76 are continuously detected and recorded from the reservoir as fluids are produced and injected downhole at location 78, e.g., via an injection well 82.
  • These microseismic tremors 76 are from the result of stress changes induced by the injection pulses 88 in the reservoir and/or from oil production activities.
  • micro-earthquakes 76 that are generated in the reservoir layers due to shear slippage in rocks induced by fluid movement. These micro-earthquakes are recorded on the seismic sensors 72, 74, or geophones, that are deployed at the earth's surface and in boreholes in the test area. These microseisms 76 are detected as the fluids move in the reservoir.
  • the system continuously detects and records the passive microseismic events 76 emanated from the reservoir as fluids are produced and injected 78. Accordingly, three-dimensional continuously and real-time reservoir monitoring is provided as the fluids are produced from and injected into the reservoir.
  • the distributed network of permanent surface sensors 72 and permanent multi-level sensors 74 in a borehole are used to acquire synchronized GPS time-stamped microseismic data.
  • Universal time or GMT is obtained from GPS satellite receivers that are connected to the recorder.
  • the data is collected at each sensor and recorded in a central recording system.
  • Each sensor in the network is surveyed for its location, e.g., in the Cartesian coordinate system as x,y,z values, and in a spherical coordinate system as r , ⁇ , ⁇ for radial distance, zenith, and azimuth, respectively.
  • the sensors are precisely orientated in the same configuration before cementing in place.
  • the orientation of the borehole sensors is determined after the installation is complete by generating a controlled seismic source at measured azimuth directions around the well.
  • the detected first arrival from the known seismic azimuth source at each sensor is analyzed in order to precisely determine its orientation.
  • estimates of microseismic source or hypocenter location are made by selecting the first arrival times of P-waves and S-waves events (or first breaks) from the recorded seismograms.
  • Hodogram analysis as shown in FIG. 4D , provides the polarization direction of the waves, and the velocity of the reservoir rock obtained from other measurements in the area are used for tomographic inversion of the picked travel times to obtain the range for the source point of the microseismic event, or the hypocenter.
  • the high-density microseismic network employs triaxial or 3-component geophones capable of measuring artifact-free response over a frequency range of 10-500Hz.
  • the sensor elements are oriented mutually orthogonal to each other to ensure the detection of microseismic waves with particle motion in all orientations.
  • the sensors detect microseismic source events that radiate from the rock-failure surface and emanate from within the reservoir.
  • Microseismic analysis techniques which are well known to those of ordinary skill in the art, are adapted to integrate the high-density measurements at the surface with those made in the borehole for the purpose of determining the microseismic events radiated from the source location. For each microseismic event, it is first necessary to determine the slip direction or source mechanism before analyzing for source parameters.
  • the network of sensors can be calibrated by stimulating the reservoir in order to induce microseismic events.
  • calibration is achieved by performing an injector pulse test, in which water injected in nearby injection wells is pulsed at predefined intervals. Explosive charges can be detonated in a nearby well at predefined depth levels in the reservoir. The resulting shock waves are detected at the surface and borehole sensors as seismic events with a delay time corresponding to the distance of the sensor from the source location.
  • the reservoir volume is idealized as a plurality of grid blocks, e.g., cubes of equal dimensions, which represent the reservoir matrix.
  • These grid blocks in such a cellular model can either have a shear slippage, with resulting microseismic activity, or have no activity.
  • contiguous grid blocks contain microseismic events emanated from within, they can be due to a system of fractures that have been temporarily or permanently displaced by the fluid flow from water injection or oil production.
  • the network of microseismic events form a conductivity network that forms input to reservoir simulation for computing fluid flow through such network.
  • the microseismic emissions from the reservoir are calibrated by correlating with induced activity in the reservoir.
  • the rates of fluid injection and production in the reservoir are varied or 'pulsed' at the well locations and their effects on detection and recording of microseismicity in the monitoring well and the surface sensors are examined.
  • the microseismicity detected above the ambient noise threshold due to such controlled pulsing of reservoir provides a correlation with the reservoir pressure and flow rate.
  • the processed microseismic attributes also need to be correlated with the spatial distribution of surface sensors and vertical antenna in the monitoring well.
  • the processing architecture for the microseismic system consists of signal processing of recorded seismograms from the surface and the bore-hole sensors and integrating the results of the total system.
  • the surface data is summed over time windows, the recorded seismic energy in the data is migrated using a velocity model in the area of study and epicenter locations for the microseismic events and their recorded time of occurrence are corrected.
  • These epicenters of microseismic events are related to the hypocenters of events derived from the processing of the microseismic recording in the borehole sensors.
  • the time synchronous events for the hypocenters located at various reservoir depths for the two sensor systems (surface and well bore sensors) are matched for interpretation of shear slippage in the zones of weakness in reservoir rocks.
  • FIGs. 4A and 4B show the compressional, or P-waves, and shear, or S-waves, from the source measured at the surface sensors and borehole sensors, respectively.
  • the difference between the arrival times of P-and S-waves provide the distance between the source and receiver locations.
  • the seismic wave velocity model, from source to the sensors, for P- and S-waves, are used for resolving the source locations using a tomographic technique.
  • FIG. 4D shows hodograms of seismic waves, as the terminus of a moving vector for particle motion recorded in the three component sensors.
  • the recorded data are analyzed for the hodograms to compute the azimuth and dip for the seismic waves arriving at the sensors.
  • Hodograms computed from the recorded passive microseismic data provide the azimuth and dip for the seismic waves arriving at the sensors and are used to calculate the microseismic event source point or hypocenter locations.
  • the direction of the microseismic source to receiver is inferred from the P-wave particle motion hodograms.
  • the spectral frequency of the signal is used for estimation of the radius of rock failure and the polarity hodogram and relative amplitudes of the seismic signal components indicate the orientation of the elastic deformation surface.
  • FIG. 5 is a plot of water injection over time
  • FIGs. 6-9 illustrate data over the period of time corresponding to the plot of FIG. 5 in a process according to the present invention.
  • FIGs. 10A-10C illustrate pressure isobars before water injection, hypocenters of passive microseismic events after ramped up water injection superimposed on the reservoir map including pressure isobars, and an extrapolated fluid pathway determined from the pattern of hypocenters.
  • Microseismic data was collected in a carbonate rock reservoir. This data was plotted as shown in FIGs. 6-9 , where the shapes of larger size indicate larger magnitude events, and the shading from dark to light represent decreasing depth.
  • the data plotted in FIGs. 6-9 was plotted using commercially available seismic analysis software. Examples of suitable software include Antelope Environment Monitoring Software commercially available from Kinemetrics Inc. of Pasadena, California, USA; Atlas Data Processing Software commercially available from Nanometrics Seismological Instruments Inc. of Ontario, Canada; SonoDet commercially available from the Institute for Geophysics, University of Stuttgart of Stuttgart, Germany; and Seisan Earthquake analysis software commercially available from Norwegian Seismic Array (NORSAR).
  • FIG. 7 shows that the sensor network detected a large number of events, shown over a period of 6 hours commencing immediately after the period of high water injection. These events were clustered along a specific pattern through the area in a northwest to southeast (NW-SE) direction. It is clear that the microseismic events during water injection revealed a distinctly different trend from the events during injection shut-off. Since only the water phase was flowing around the water injectors, this enabled correlation of this abundant number of NW-SE microseismic events to the flow of the water phase. These events occurred along a narrow NW-SE pathway through which the water phase was flowing.
  • the number of events in the hypocenter swarm increased in intensity, generally due to the cumulative increase in water in the preferential fluid pathway.
  • the orientation direction of the hypocenters continued to be in a NW-SE trend, as shown in FIG. 8 , which represents microseismic events over a 6 hour period after 15 days of water injection at 40,000 barrels per day.
  • This corridor appears to be located in a zone of a high permeability pathway along which injected water preferentially advanced through the reservoir.
  • FIG. 9 shows events computed from seismograms recorded after 20 days of injection at the ambient injection and production rates. Note that there are only a few events, and the orientation is inconsistent. Closer to the injection wells they are somewhat oriented in a NW-SE trend that is consistent with the surge injection.
  • FIG. 10A shows pressure isobars and direction of the pressure transmission over time, represented by arrows on the reservoir map.
  • FIG. 10B shows the hypocenters of passive microseismic events superimposed on the reservoir map of FIG. 10A .
  • the reservoir pressure contours are compared to the distribution of hypocenters.
  • the left side shows higher pressures close to the injectors as expected.
  • the arrows indicate the pressure front advancing over time.
  • the hypocenters appear to be parallel to the pressure trend.
  • results described with respect to FIGs. 5-10C confirm that the method and system of the invention enables identification of the fluid phase (water or oil) flowing along a reservoir pathway.
  • a preferential fluid pathway can be identified and a baseline number of events per unit time can be ascertained for that fluid pathway.
  • activity associated with water flow can be identified when the number of events over a time period approaches the baseline number of events per unit time.
  • a cyclic water injection operation can include injection of water at a high rate followed by a shut in period, and repeating these steps for a desired number of cycles.
  • the number of microseismic events may determined and used as a baseline value, for instance, to compare to monitored microseismic events and to ascertain that the liquid moving along an identified preferential pathway is water if the number of monitored events approaches the number of baseline events.
  • the microseismic data is gathered for processing by a computer 122 as shown, for example, in FIG. 11 , which can implement a seismic server.
  • a communication interface 124 connects to the sensors, and the microseismic data is acquired by a processor 126 for storage in a memory 128.
  • the processor 126 and memory 128 can be implemented by any known computing system, such as a microprocessor-based server or personal computer.
  • a data analysis program 130 is provided in the memory 128 and executed by the processor 126 for performing the operations, steps, and features of the process flow described in FIGs. 1A and 1B , or alternatively as shown in FIGs. 1A , 1B and 2 .
  • the processor 126 can include, as hardware and/or software, tomographic analysis means 132 known in the art for generating tomograms corresponding to the acquired microseismic data, and performing the comparisons of the monitored events to the baseline events.
  • the computer 122 can include or be connected to a GPS system 134, which can incorporate or be connected to a GPS system associated with the sensors, for managing the received microseismic data according to their time of acquisition.
  • the computer 122 can include and/or be connected to an output device 136 which can include a display 138 and/or a printer 140 or other known output devices, such as plotters.
  • an output device 136 which can include a display 138 and/or a printer 140 or other known output devices, such as plotters.
  • estimates of microseismic source or hypocenter locations can be made by picking the first arrival times of P-wave and S-wave events, or first breaks, from the recorded seismograms.
  • Hodogram analysis such as shown in FIG. 4D , provides the polarization direction of the P-waves and S-waves, and the velocity characteristics of the rocks obtained from other measurements in the area are used for tomographic inversion of the picked travel times to obtain the range for the source point of the respective microseismic event or the hypocenter.
  • the present invention advantageously provides a method of and system for continuously detecting these passive microseismic events or micro-earthquakes for monitoring fluid pathways in a hydrocarbon reservoir.
  • Anisotropic fluid flow or uneven directional flow rate is commonly associated with reservoir production and injection operations.
  • fluid flow anisotropy, or pathways can be mapped, and the reservoir phase (oil or water) of fluids moving along such pathways in a reservoir volume can be identified, between and away from wells.
  • Mapping of microseismic hypocenters within time windows provides the frequency of occurrence of microseismic emissions, i.e., the number of microseismic hypocenters per unit time. The difference in the frequency of occurrence is used for discriminating oil transport from water transport through the reservoir flow pathways. The result enhances reservoir model accuracy, reservoir management, and improved oil recovery.
  • the method of, and system for identifying the type of reservoir fluid moving along flow pathways using passive seismic emissions advantageously allows operators of a producing field to optimize reservoir management and improve overall oil recovery.
  • reservoir engineers can plan appropriate development of production and/or injection wells. For instance, when it is determined by the method and system of the present invention that the type of fluid moving at a certain location along a pathway is water, placement of production and injection wells at that location can be avoided. If existing wells have already been drilled in those regions, attempts at production and/or injection operations can be suppressed.
  • reservoir engineers can plan development of production wells in the region of that pathway, or if existing production wells have already been drilled in those regions, extraction operations can be maintained or resumed.
  • reservoir engineers can plan the locations of injection wells, generally avoiding areas where either type of fluid pathways exist.
  • the information derived using the system and method of the present invention provides substantial economic benefit, in terms of the efficiency of extraction. Furthermore, by avoidance of drilling or reopening production wells in regions where the preferential fluid pathway contains water, the cost of removing water is obviated. Furthermore, in the case of saline water, suppression of extraction provides the additional benefit of reducing the exposure of equipment and pipelines to the corrosive effects of saltwater.

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Claims (14)

  1. Verfahren zur Ermittlung, ob eine nicht bekannte Flüssigkeit, die sich in einer Öl-haltigen Reservoir-Gesteinsformation bewegt, Wasser oder Öl ist, wobei die Öl-haltige Reservoir-Gesteinsformation bei normaler Ölförderung zumindest eine Förderbohrung und zumindest eine Wassereinspritzung aufweist, und wobei das Verfahren aufweist:
    a. Ermitteln eines bevorzugten Flüssigkeitspfads in der Öl-haltigen Reservoir-Gesteinsformation, von dem Mikroseismik ertastet wird, welche mit Öl- und Wasserbewegungen in Zusammenhang stehen;
    b. Erstellen eines Basiswerts für passive Mikroseismik-Ereignisse pro vorgegebener Basiszeiteinheit, wobei der zumindest eine Basiswert einer oder mehrerer ist von:
    (i) eine Basisanzahl von ölbezogenen Mikroseismik-Ereignissen, die in dem bevorzugten Flüssigkeitspfad während einer Zeitspanne auftreten, in der die Wassereinspritzung geringer ist, als eine Wassereinspritzung bei der normalen Ölförderung;
    (ii) eine Basisgröße von ölbezogenen Mikroseismik-Ereignissen, die in dem bevorzugten Flüssigkeitspfad während einer Zeitspanne auftreten, in der die Wassereinspritzung geringer ist, als eine Wassereinspritzung bei der normalen Ölförderung;
    (iii) eine Basisanzahl von wasserbezogenen Mikroseismik-Ereignissen, die in dem bevorzugten Flüssigkeitspfad während einer Zeitspanne auftreten, in der die Wassereinspritzung grösser ist, als eine Wassereinspritzung bei der normalen Ölförderung; und
    (iv) eine Basisgröße von wasserbezogenen Mikroseismik-Ereignissen, die in dem bevorzugten Flüssigkeitspfad während einer Zeitspanne auftreten, in der die Wassereinspritzung grösser ist, als eine Wassereinspritzung bei der normalen Ölförderung;
    c. Überwachen von Mikroseismik-Ereignissen in dem bevorzugten Flüssigkeitspfad während der normalen Ölförderung, um eine zugehörige Anzahl oder Größe von Mikroseismik-Ereignissen während einer vorgegebenen Überwachungszeit-Intervalleinheit abzutasten;
    d. Vergleichen der ertasteten Anzahl oder Größe von Mikroseismik-Ereignissen während einer vorgegebenen Überwachungszeit-Intervalleinheit mit der Basisanzahl oder Basisgröße von passiven Mikroseismik-Ereignissen pro vorgegebener Basiszeit;
    wobei das Verfahren gekennzeichnet ist durch
    e. das Ermitteln, dass
    wenn der Basiswert in Schritt (b) eine Anzahl oder Größe ist, die Wasser entspricht, die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, Wasser ist, wenn die Anzahl oder Größe der abgetasteten Mikroseismik-Ereignisse während der vorgegebenen Überwachungszeit-Intervalleinheit den wasserbezogenen Basiswert erreicht, oder
    wenn der Basiswert in Schritt (b) eine Anzahl oder Größe ist, die Öl entspricht, die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, Öl ist, wenn die Anzahl oder Größe der abgetasteten Mikroseismik-Ereignisse während der vorgegebenen Überwachungszeit-Intervalleinheit den ölbezogenen Basiswert erreicht, wobei
    - das Erstellen eines Basiswerts in Schritt (b) beinhaltet das Erstellen einer ersten Basis für eine Zeitspanne, während derer die Wassereinspritzung geringer ist als die Einspritzrate während der normalen Ölförderung und
    die Erstellung eines zweiten Basiswerts beinhaltet, wenn die Wassereinspeisung grösser ist als während der normalen Ölförderung;
    - Schritt (d) den Vergleich der abgetasteten Anzahl von Mikroseismik-Ereignissen während der vorgegebenen Zeit-Intervalleinheit mit dem ersten Basiswert und mit dem zweiten Basiswert beinhaltet;
    - Schritt (e) das Bestimmen beinhaltet, dass die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, Öl ist, wenn die abgetastete Anzahl von Mikroseismik-Ereignissen während der vorgegebenen Überwachungszeit-Intervalleinheit näher an dem ersten Basiswert liegt als der zweite Basiswert; und
    - Schritt (e) das Bestimmen beinhaltet, dass die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, Wasser ist, wenn die abgetastete Anzahl von Mikroseismik-Ereignissen während der vorgegebenen Überwachungszeit-Intervalleinheit näher an dem zweiten Basiswert liegt als der erste Basiswert.
  2. Verfahren gemäß Anspruch 1, wobei
    Schritt (b), das Erstellen eines Basiswerts, weiter aufweist:
    - Abtasten einer ersten Anzahl von passiven Mikroseismik-Ereignissen während einer ersten vorgegebenen Zeitspanne, um eine erste Kennzahl zu bestimmen, wobei die erste Anzahl von passiven Mikroseismik-Ereignissen abgetastet wird, wenn die Wassereinspritzung geringer ist als die Einspritzrate während der normalen Ölförderung;
    - Erfassen der ersten Anzahl von passiven Mikroseismik-Ereignissen;
    - Erhöhen der Wassereinspritzrate, um die Einspritzrate bei der normalen Ölförderung zu überschreiten;
    - Abtasten einer zweiten Anzahl von passiven Mikroseismik-Ereignissen während einer zweiten Zeitintervalleinheit, um eine zweite Kennzahl zu bestimmen, wobei die zweite Zeitintervalleinheit beginnt, wenn die Wassereinspeisung grösser ist, als die Wassereinspeisung bei der normalen Ölförderung; und
    - Erfassen der zweiten Anzahl von passiven Mikroseismik-Ereignissen; wobei
    - Schritt (a) - das Ermitteln eines bevorzugten Flüssigkeitspfads - auf der Erfassung der ersten Anzahl von passiven Mikroseismik-Ereignissen und der zweiten Anzahl von passiven Mikroseismik-Ereignissen basiert;
    - Schritt (c) das Überwachen von passiven Mikroseismik-Ereignissen in dem bevorzugten Flüssigkeitspfad während der normalen Ölförderung aufweist, um eine dritte Anzahl von passiven Mikroseismik-Ereignissen während einer dritten vorgegebenen Zeitintervalleinheit abzutasten, um eine dritte Kennzahl zu bestimmen;
    - Schritt (d), das Vergleichen der dritten Kennzahl mit der ersten Kennzahl und der zweiten Kennzahl aufweist;
    - Schritt (e), das Bestimmen aufweist, dass die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, Öl ist, wenn die dritte Kennzahl näher an der ersten Kennzahl liegt als die zweite Kennzahl; und
    - Schritt (e) dass Bestimmen aufweist, dass die Flüssigkeit, die die Mikroseismik-Ereignisse verursacht, als Wasser bestimmt wird, wenn die dritte Kennzahl näher an der zweiten Kennzahl liegt als die erste Kennzahl.
  3. Verfahren gemäß Anspruch 1, wobei das Abtasten ein verzweigtes Netzwerk von Sensoren verwendet, das über einem Bereich positioniert wird, der einem unterirdischen Öl-haltigen Reservoir entspricht.
  4. Verfahren gemäß Anspruch 3, wobei das verzweigte Netzwerk von Sensoren zumindest einen Sensor an der Erdoberfläche und zumindest einen Sensor an einer unterirdischen Position aufweist.
  5. Verfahren gemäß Anspruch 4, wobei das verzweigte Netzwerk von Sensoren eine Vielzahl von Sensoren an der Erdoberfläche aufweist.
  6. Verfahren gemäß Anspruch 3, wobei das verzweigte Netzwerk von Sensoren eine Vielzahl von unterirdischen Sensoren aufweist.
  7. Verfahren gemäß Anspruch 3, wobei das verzweigte Netzwerk von Sensoren eine Vielzahl von Sensoren an der Erdoberfläche und eine Vielzahl von Sensoren an unterirdischen Positionen aufweist.
  8. Verfahren gemäß Anspruch 6 oder 7, wobei zumindest bestimmte Sensoren der Vielzahl von unterirdischen Sensoren in unterschiedlichen Tiefen positioniert sind.
  9. Verfahren gemäß einem der Ansprüche 4, 5 und 8, wobei die Oberflächensensoren einbetoniert sind.
  10. Verfahren gemäß Anspruch 3, wobei jede Abtastzeit eines jeden Sensors durch einen zugehörigen GPS-Empfänger vorgegeben ist.
  11. Verfahren gemäß einem der Ansprüche 4, 6 oder 7, wobei die Sensoren 3-Komponenten-Sensoren aufweisen.
  12. Verfahren gemäß Anspruch 1, wobei jeder der ersten und zweiten Basiswerte die Größe für passive Mikroseismik-Ereignisse darstellt, die mit Wasser in Verbindung gebracht werden.
  13. Verfahren gemäß Anspruch 1, wobei jeder der ersten und zweiten Basiswerte die Magnitude für passive Mikroseismik-Ereignisse darstellt, die mit Öl in Verbindung gebracht werden.
  14. Verfahren gemäß Anspruch 2, wobei beim Schritt des Bestimmens, ob die Flüssigkeit Öl oder Wasser ist, auf dem Basiswert basiert, der die Anzahl seismischer Ereignisse abbildet, und diese Bestimmung bestätigt wird durch die Verwendung von Basiswerten und gemessenen Werten für die Größe.
EP09713844.0A 2008-02-29 2009-03-02 Überwachung von sich entlang strömungswegen in einem produktionsölfeld bewegendem reservoirfluid unter verwendung von passiven seismischen emissionen Active EP2260177B1 (de)

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CN102089497B (zh) 2014-12-10
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